Sidewall Core Samples Research Articles

Characterization of subaerial lava flows of the presalt strata in the Santos Basin based on basic well logs

It is hard to identify volcanic morphologies using well logs to support technical decisions during well drilling and the acquisition of geological information. Therefore, this study was carried out on the volcanic sequence present in the Presalt interval of the Santos Basin, Brazil, which is referred to as the Camboriú Formation. This section was described in a previous study using image well logs as a succession of subaerial lava flows formed mainly by compound pahoehoes, sheet pahoehoes and rubbly pahoehoes. Based on sidewall core samples and petrophysical, geochemical and mineralogical reports, we identified five electrofacies from gamma ray, resistivity, sonic, density and neutron logs, representing patterns for identifying lava flows in subaerial sequences. In addition, we applied a porosity quantification method that resulted in a method for obtaining information from the matrix and presented coherent values in facies that did not present amygdalae or breccias and inferring altered zones from variations in resistivity and density logs or from cross-plots. Patterns of well log responses were defined for each type of lava flow present in the studied well, as was the inference about the most favorable facies for reservoirs. This methodology, which uses basic well logs from basalts, is unprecedented in the Presalt sequence and can be easily used to evaluate this exploratory frontier because of its close association with subaerial volcanism.

Palynology of the Triassic–Jurassic transition of the Danish Basin (Denmark): a palynostratigraphic zonation of the Gassum–lower Fjerritslev formations

The Upper Triassic–Lower Jurassic succession in the Danish Basin is penetrated by many deep wells that were drilled during former hydrocarbon exploration campaigns, but it is today targeted for geothermal energy and storage of CO2. The Stenlille salt dome on Sjælland sandstones of the Gassum Formation, sealed by the overlying Fjerritslev Formation mudstones, has been used for decades as a seasonal storage for natural gas. With its comprehensive dataset of seismics, geophysical well logs and conventional core data from 20 wells, the Stenlille succession serves as a model for other salt domes currently being evaluated as potential CO2 storage sites in the basin. Over the last decade the cored Triassic–Jurassic boundary succession has contributed to the understanding of environmental and palynological events during the end-Triassic mass extinction. Core, sidewall core and cutting samples from several of the closely situated Stenlille wells are here used to establish a high-resolution palynostratigraphic zonation scheme covering the entire Rhaetian to Sinemurian succession by integrating new analyses with previously published data. The palynological dataset has allowed the recognition of nine formally described spore-pollen zones, of which eight are new, while two previously described dinoflagellate cyst zones are subdivided into three informal subzones each. The palynological zonation is integrated with a sequence stratigraphic framework and will form the basis for the dating of future well sections in the Danish Basin and other basins and for correlation to outcrops. The large palynological dataset further shows that the vegetation around the Danish Basin was remarkably stable during the early to middle Rhaetian, but that events related to the emplacement of the Central Atlantic Magmatic Province accelerated ecosystem changes for c. 175 ky in the late Rhaetian and earliest Hettangian, including ∼25 ky of successional recovery before the terrestrial ecosystem had again stabilised.

Petrogenesis of Early Cretaceous volcanic rocks in Santos Basin, offshore SE Brazil: evidence for the Tristan da Cunha plume

ABSTRACT The Santos Basin comprises the most voluminous hydrocarbon accumulations in its ‘Pre-salt’ reservoirs. Magmatic rocks have been recorded in the basin mostly by the tholeiitic basalts (Camboriú Formation) within its rift megasequence at Hauterivian time. Recent studies have shown that magmatic rocks are also found interbedded with Aptian sedimentary rocks in the basin, related to its post-rift (mostly Aptian) megasequence. This paper presents petrological data obtained from sidewall core samples of magmatic rocks interbedded with Early Aptian coquina in a well drilled in the Santos Basin. The well comprises six magmatic sections of alkaline basalts being overlain and underlain by the Barra Velha limestones. The basalts are mostly plagioclase-phyric, amygdaloidal rocks but vary in texture and modal compositions. Magmatic compositions seem to have been slightly affected by alteration processes. Basalts comprise an alkaline, miaskitic series with relatively evolved compositions (MgO = 5.55 ± 1.50 wt%; Ni < 220 ppm; Cr < 400 ppm). The patterns in the Primitive Mantle normalized multielement diagram displays the typical Nb peak (0.3 < La/Nb(N)<0.7) of the OIB. Geochemical modelling showed that basalts within five magmatic sections are not cogenetic by differentiation, representing basaltic flows emitted from different vents. Modal batch partial melting model indicates that it is possible, although unlikely, to generate the differences in La/Yb(N) and Zr/Y ratios of the least evolved samples in the studied well by different partial melting degrees (0.5–11%) from the same mantle source. Binary mixing models using lithogeochemical datapoint to a role for the Tristan da Cunha plume tail in the petrogenesis of the alkaline basalts with no clear evidence for a possible role for the local subcontinental lithospheric mantle. The results of the petrogenetic models are consistent with a shallow MOHO and a high-temperature mantle below part of the Santos Basin in Early Aptian time.

Viscosity prediction using image processing and supervised learning

The paper implements image processing followed by supervised learning to predict the viscosity of hydrocarbon present at a specific reservoir depth in a heavy oil reservoir located in California, USA. Viscosity is predicted from white-light and UV-light images of side-wall core samples extracted from specific depths along the wellbore. The fluid viscosity primarily ranges from 5 to 600 cP at a temperature of 180 degF. The white-light and UV-light images are available for 680 side-wall core samples. Sobel, Sato, Hessian, LBP, and Multi-Otsu filters extract meaningful features from red, green, and blue pixel intensities of the white-light and UV-light images. The distribution of pixel-wise values for each filtered/raw image is further processed to derive histogram-based features. As a result, 600 features are extracted for each side-wall core sample. Thresholds based on the variance, MI score, F score, and Person’s r are imposed to select the most informative features for the viscosity prediction. Compared to filtered white-light images, raw RGB white-light images have stronger viscosity association. On the contrary, filtered UV-light images have stronger viscosity association as compared to raw RGB UV-light images. Supervised learning is deployed using the resulting features in both regression and classification of target viscosity. For the prediction of continuous-valued viscosity (regression), random forest is the best performer with a mean absolute error of 27 ∓ 3 cP. For the viscosity classification, high-viscosity and low-viscosity samples can be very well detected at a F1 Weighted Score higher than 0.95 and Matthew’s Correlation Score higher than 0.9. Overall, for viscosity prediction, classification is much superior to the regression. The novel image-based viscosity prediction workflow will help lower the cost and improve the precision of laboratory-based viscosity measurements and simultaneously contribute to a high-resolution reservoir model development.

Total organic carbon variability of lower Jurassic successions in the Mandawa Basin, SE Tanzania

Over many decades, an understanding of total organic carbon (TOC) variability in various sedimentary basins has been constrained by the availability of suitable samples for geochemical analysis. Many attempts rely on selected sidewall core or cuttings samples, which do not provide a continuous lithological record of the succession. As a result, TOC variability as a response to facies evolution is often underestimated. An advancement in TOC evaluation from well logging techniques often has permitted a continuous analysis of source rock intervals, while eliminating issues associated with obtaining discrete physical samples. Geochemical and wireline geophysical logs investigation here aimed at constraining TOC variability and depositional conditions prevailing during the early Jurassic in the Tanzanian Mandawa Basin (Mbuo, Nondwa and Mihambia Formations), which to date are poorly documented. TOC was deduced from both well cuttings samples and wire log data. Depositional conditions were defined via the use of spectral Gamma-Ray (Th/U, U) logging and lithofacies data. Sediment composition and TOC from cuttings were compared to illustrate how organic matter distribution is influenced by changes in sediment type. Complex mineral composition of heterolithic facies dominated log-response, complicated log interpretation, and thus limited the effectiveness of well logging techniques to predict TOC. Cuttings data reveal three organic-rich intervals, i) at the transition of Upper Mbuo to basal Nondwa Formation with the highest TOC of 3.5 (wt%), ii) in the Nondwa Formation with a TOC of 2 (wt%), and iii) in the Mihambia Formation with a TOC of 2.8 (wt%). An inverse linear relationship between Th/U and TOC signifies relatively shallow deposition in a well-mixed water column under oxic conditions. Intervals with higher TOC imply organic matter preservation under suboxic conditions upon two marine incursions in the Mihambia and Nondwa Formations, whereas a limnic environment prevailed at the Upper Mbuo to Nondwa transition. Inverse trends in TOC versus clastic components, a positive linear relationship between TOC and carbonates, and higher amount of clastics (>57 wt%) in the Mbuo and Mihambia Formations suggest a dominantly clastic sedimentary system with relatively stable carbonate and organic matter input in proximity to the source area. We, therefore, argue that the organic rich intervals observed in the Upper Mbuo, Nondwa and Mihambia Formations were deposited during periods of higher organic productivity driven by a rise in eustatic sea level, and coincide with a decline in terrigenous input from the hinterland.

Identifying and quantifying Mg-clays in well logs using new petrophysical methods: A case study from the Brazilian pre-salt

The Santos Basin, located in offshore southeast Brazil, is the site of several giant oilfields of the Pre-salt interval. The limestones from the Barra Velha Formation (Aptian in age) are complex, highly heterogeneous, and usually are associated with Mg-clays, being interpreted as deposited in an unusual alkaline lacustrine rift system that developed during the opening of the South Atlantic Ocean (Lower Cretaceous). The reservoirs of the Barra Velha Formation show exceptional reservoir quality and are sealed by marine evaporites of the Ariri Formation. Although clays traditionally present a negative impact on reservoir quality, Mg-clays (such as Mg-smectite, kerolite and talc) are prone to dissolution during diagenesis, which can increase the reservoir quality. However, in areas of the reservoir where Mg-clays are still present, they can significantly reduce it. The distribution of Mg-clays at the field, inter-field and basin scale has important implications for exploration and production. As these Mg-clays usually lack radioactive elements and therefore present a low gamma ray response, the usual petrophysical interpretation of clay-rich zones differs from the conventional method. This work proposes an algorithm to identify zones in a well with (1) presence of “pure Mg-clays” (i.e. not mixed with non-Mg-clays); (2) presence of “dirty Mg-clays” (i.e. mixed with non-Mg-clays or organic matter); and (3) absence of Mg-clays and another to quantify the Mg-clay volume in the wells. The study was carried out using well logs from 27 wells along with sidewall core samples. The occurrence of Mg-clays in the wells was confirmed by thin section description, supported by SEM- EDS and XRD analyses and allowed the understanding of the distribution of Mg-clays in the Sapinhoá Field, which are more abundant in structural lows due to better preservation whereas in higher structural positions clays were more affected by diagenetic alterations. The new algorithms proved to be reliable methods to perform both qualitative and quantitative detection of Mg-clay-rich zones using well logs and allowed the better identification of well-sections where this type of clay is present, providing a good-quality input for facies distribution. This study contributes to add new methodologies, which can be used in the improvement of petrophysical interpretations in zones with the presence of such complex clays and thus reducing the exploratory and development risks.

Controls of fracturing on porosity in pre-salt carbonate reservoirs

This work aims to improve the understanding of how fracture zones affect carbonate reservoir properties based on observations of a pre-salt well located in the Santos Basin, Brazil. The identification of fracture zones allowed for the observation of a relationship between the occurrence of rock fractures and the silicification, as the latter plays an important role in determining porosity (higher silica content may increase brittleness of the rocks therefore increasing the likelihood of creating fractures zones and fractures may be filled up reducing the total porosity). To support the proposed observation, an integrated study was conducted using borehole imaging, spectroscopy logs, and sidewall core samples. The porosities were defined using nuclear magnetic resonance log analysis, alongside sidewall core samples, and thin sections. The integration of rock samples and well data with seismic analysis was performed to analyze the presence of a regional fault system that could explain high fracture densities as well as observed silica content characteristics. The results show how different types of cement filling up the formation pores affect fracture densities and total porosity. Furthermore, it was possible to infer that the amount of silica content observed in well logs and thin sections relates to hydrothermal fluids reaching out the reservoir through regional fault systems detected in the seismic section. Therefore, this paper supports the comprehension of how diagenetic processes can significantly affect the properties of pre-salt reservoirs.

Oil biomarker signature and hydrocarbon prospectivity of Paleozoic versus Mesozoic source rocks in the Faghur–Sallum basins, Egypt's Western Desert

Exploration campaigns focusing on Paleozoic plays in the Egyptian north Western Desert Sallum and Faghur basins have been limited to date, and little has been done to investigate their hydrocarbon generation potential. A total of 284 shale, calcareous shale, coaly shale and siltstone side-wall core and cuttings samples, covering the rock succession that ranges from the Silurian Kohla Formation to the Turonian Abu Roash Formation were analyzed for source rock potential. In addition, eight reservoired Paleozoic–Mesozoic oil samples were geochemically analyzed. This paper systematically investigates (1) organic enrichment, hydrocarbon generation potential, and thermal maturity of Mesozoic as well as possible Paleozoic source rocks, and (2) composition and biomarker characteristics of crude oil samples in the study area from the far north Western Desert basins of Egypt.The Silurian Kohla and Basur and the Carboniferous Desouqy and Dhiffah siltstone and shale rock samples show overall poor and fair to good source rock potential for the Lower and Upper Cretaceous rock units, respectively. In contrast, high TOC (up to 4.83 wt%) and Rock-Eval S2 (up to 6.57 mg HC/g rock) for the Devonian Zeitoun Formation samples indicates fair to very good source potential. The Middle Jurassic Khatatba Formation samples, compared with the Devonian Zeitoun Formation or other rock units in the stratigraphic column of the study area, have the highest TOC (30.1 wt%) and the highest S2 (26.9 mg HC/g rock), indicating fair to excellent source rock potential. These high values of the Khatatba Formation are locally related to organic-rich coaly shales and calcareous shale intervals. The Rock-Eval results indicate an overall dominance of Type-III kerogen with strongly varying OI values. This highly gas-prone character for most samples was confirmed petrographically by abundant vitrinite phytoclasts and recycled organic matter. Coals and coaly shale facies from the Alam El Bueib and Khatatba formations that contain liptinitic materials may represent Type-III kerogens that are capable of generating gas with minor oil. Based on Rock-Eval Tmax and HI results, the Zeitoun and Khatatba samples range from early to peak oil window. This is consistent with the Ro measurements of the Paleozoic Zeitoun samples (0.65–1.02%) and the Middle Jurassic Khatatba samples (0.59–1.01%).The Faghur oils are light (35°–46° API gravity), belong to a single genetic family and are non-biodegraded based on wide-ranging n-alkanes. Abundant tricyclic diterpanes, C24 tetracyclic terpane, C27 Ts trisnorneohopane, diahopane, cyclohexanes, C29 steranes and rearranged steranes and low to very low gammacerane and extended hopanes are common molecular signatures of the analyzed light oil and condensate samples. These findings indicate a relatively oxic fluvio-deltaic environment for the corresponding clay-rich coaly shale and calcareous shale source rocks that contain predominantly higher land-plants with negligible algal/bacterial organic materials. Based on saturated- and aromatic-maturity parameters, the analyzed oils were inherited from peak–late mature source rock.

POROSITY VERSUS DEPTH CHARACTERISTICS OF SOME RESERVOIR SANDSTONES IN WESTERN INDONESIA

Porosity is a petrophysical property that always draws attention due to its central role in determiningstorage capacity of hydrocarbon reservoirs. Accuracy for predicting porosity in reservoir affects much ofmany petroleum production related activities. Accordingly, various attempts have been devoted to study andmodel rock porosity including its relation with depth. In this study porosity data from as many as 4654 coresamples (1773 full-diameter core plugs and 2881 sidewall core samples) is used. The core samples were takenfrom 549 wells in 222 fi elds/structures located in eight producing sedimentary basins in western Indonesia.Main results of the study are facts that existing porosity-depth models derived from data obtained from otherregions are not usable for Indonesian cases, and therefore porosity-depth models are established for theeight sedimentary basins. It is hoped that these models can contribute signifi cantly to the understanding ofrock porosity trends with depth in western Indonesia.

Gas and foam injection with CO2 and enriched NGL's for enhanced oil recovery in unconventional liquid reservoirs

In order to extend the economic life of existing horizontal wells and improve oil production for newly drilled wells in unconventional liquid reservoirs (ULR), testing of enhanced oil recovery (EOR) techniques is essential. The interaction of the fluids in the fractures system with the oil stored in the matrix is the key to understanding and implementing all EOR techniques in ULR. This study focuses on investigating the performance of different EOR agents (CO2, rich gas, and foam) through laboratory tests.A correlated set of Huff-n-Puff experiments were performed at reservoir temperature using different gases and foam on side-wall core samples from the Wolfcamp formation. The experimental setup was mounted into a Computed Tomography Unit (CTU) to capture time-lapse CT images which were used to monitor the fluid movement inside the core plugs, track the foam quality in glass beads pack around the cores.Various gases (CH4, a mixture of 85% CH4 - 15% C2H6, enriched gas (50% CH4 - 50% C2H6), and CO2) were used for Huff-n-Puff experiments at reservoir conditions to explore the effects of gas composition on the recovery factor in ULR. Enriched gas (50% CH4 - 50% C2H6) showed the most promising potential of improving oil recovery in the Wolfcamp formation. An increase in pressure does not always correspond to higher oil recovery in gas Huff-n-Puff experiment. During the CO2 injection experiment conducted at 5000 psi, we recovered a smaller amount of oil than previous experiments performed at lower pressure. The primary mechanism of gas injection is multi-contact miscibility, and diffusion has a minor effect on enhancing oil recovery in ULR. Surfactants enhance oil recovery by wettability alteration and interfacial tension (IFT) reduction. Implementing surfactants into completion fluids or re-frac fluids results in additional oil recovered from ULR. From the results obtained, a combination of EOR techniques (foam or sequencing surfactant and gas injection) opens the possibility to achieve optimum oil recovery in ULR.

Seismic characterization and origin of clinoforms in lacustrine depositional environments: a case study from the Cretaceous of the South Atlantic

Abstract The lacustrine Itapema Formation in the Santos Basin locally comprises 10 2 m thick clinoforms identified seismically and corroborated by several well penetrations. Individual clinoforms, as proven by well penetrations, are composed of 10 2 m thick successions of basinward-dipping molluscan grainstones and rudstones. Manual dip picking of borehole images shows upward-increasing dips consistent with seismic geometries and a predominance of longshore sediment transport. Clinoforms are bound at their top and base by strata with significantly lower dips recognizable on both seismic and borehole images. Elevated gamma-ray log responses together with sidewall core samples indicate that these intervals correspond to more argillaceous facies which are interpreted as lake flooding events. While the existence of bona fide clinoforms is demonstrated by a range of subsurface data, their precise origin remains enigmatic. The majority of the bivalve genera that make up the grain-supported carbonates appear to be infaunal or semi-infaunal. As such the clinoforms represent large bars produced through the re-working of bivalves from lower-energy depositional environments by shore-parallel currents.

Multi-scale characterization of unconventional tight carbonate reservoir: Insights from October oil filed, Gulf of Suez rift basin, Egypt

The thick Eocene carbonate deposits that are newly ascribed as Radwany Formation (previously Thebes Formation) in the October basin within the Gulf of Suez region, are of particular interest for hydrocarbon exploitation. However, no efforts have been directed to investigate their petrophysical characteristics and pore system. This study aims to investigate the petrophysical characteristic, pore system and formation potentiality as a reservoir rock. Thirteen sidewall core samples and sixty thin sections from OCT-X well were studied in order to investigate the lithological characteristics, porosity network. In addition, well logging data and petrophysical and geochemical laboratories measurements including Nuclear Magnetic Resonance (NMR) porosity technique were used to define the petrophysical characteristics. The investigated work revealed that: 1) the pore system is a combination of depositional and diagenetic processes. 2) the dominant porosity types include fracture, inter-particle, intra-particle and moldic porosity; NMR indicates mesopores to macropores, 3) petrophysical evaluation and geochemical analysis indicates a self-sourced unconventional reservoir based on its organic richness characteristics unconventional resource opportunity as tight carbonate reservoir, 4) the basal part of the Radwany Formation has a high potential to store hydrocarbon, and it is a potential conventional resource. 6) The linking trends between the petrophysical parameters with sediment microfacies were defined in the studied section, where a significant increasing trend line has been inferred in the direction from wackestone microfacies to packstone microfacies. Finally, the diagenetic process through time has greatly controlled the petrophysical parameters of the Radwany Formation. The gap between Source and Reservoir rocks has been defined based on integrated geochemical and petrophysical characteristics. The studied section has unique multiscale characterization as unconventional and conventional resource.

Coupled nano-petrophysical and organic-geochemical study of the Wolfberry Play in Howard County, Texas U.S.A.

This research investigates the use of mercury injection capillary pressure (MICP) analysis for pore structure characterization and wettability droplet analysis for mm-scale assessment of wetting properties, on rotary side-wall core samples in the bottom section of Lower Spraberry (Leonard shale) and Wolfcamp A units from Element Petroleum's Rogers #3804 E well in the Midland Basin, Howard county, Texas. Porosity, permeability, total organic carbon (TOC), pyrolysis and X-ray diffraction data were also acquired for both the Rogers #3804 E and Wright 44 #1 E wells. The roles of organic matter quantity, quality and maturity, along with mineralogy, and grain size, are considered in the development of multiple pore systems at nm-μm sizes and their implications for petroleum production. The Lower Spraberry unit is found to contain greater porosity and permeability (and associated lower tortuosity) than the Wolfcamp A unit. More importantly, the two formations show disparate pore-throat size distributions, with the Lower Spraberry unit samples containing more inter- and intra-particle pores (43.1 ± 27.1 nm in pore-throat diameters) conducive to petroleum movement and production, while the Wolfcamp A unit samples possesses smaller pores (10.5 ± 5.45 nm) that are probably organic matter-hosted. The amount of S1 (an indicator of oil content) is closely related to the proportion of pore volume controlled by 2.8–50 nm in pore-throat sizes that are likely organic matter-related. Differences in the behavior of petroleum production from the Rogers #3804 E (with slow decline) and Wright 44 #1 E (with steep decline) wells are manifested in the oil saturation index (S1 vs. TOC), which is tantalizingly linked to the differences in the predominant pore-throat size distributions observed above.

Late Triassic dinoflagellate cysts from the Northern Carnarvon Basin, Western Australia

The Late Triassic radiation of cyst-forming dinoflagellates in the Southern Hemisphere is investigated in the Northern Carnarvon Basin, Western Australia. This major depocentre, situated on the southern margin of the Tethys Ocean, accumulated extensive deltaic and shallow marine successions at this time, that frequently host early dinoflagellate cyst assemblages. Numerous petroleum exploration wells in the basin have penetrated the fluvially dominated Mungaroo Formation and shallow marine Brigadier Formation, of Anisian–Norian and Rhaetian ages, respectively. Consequently, huge numbers of cuttings and sidewall core samples from these northwest prograding deltaic systems are available for study. Many of the dinoflagellate cysts from the Mungaroo and Brigadier formations have not been taxonomically formalised, including many forms that are used in open nomenclature within the oil and gas industry. This study formally documents these occasionally abundant and diverse dinoflagellate cyst assemblages with the aim of providing a consistent taxonomic framework for future work on the Upper Triassic successions of the Northern Carnarvon Basin. This will aid the recognition of individual flooding events via their characteristic palynomorph signatures and help to build on significant recent advances in regional sequence stratigraphy. One new genus, 14 new dinoflagellate cyst species and one new subspecies are described from the most diverse Late Triassic dinoflagellate assemblage yet published. A further nine genera and 15 dinoflagellate species are also recorded from the Carnian–Rhaetian R. wigginsii, W. listeri, H. balmei, R. rhaetica and D. priscum dinoflagellate zones. The documented assemblages are not only significant biostratigraphically, but it is also postulated that high diversity Triassic dinoflagellate cyst associations were paleoclimatically controlled, and were likely confined to the temperate and cool temperate paleolatitudes.

An Investigation on the Effect of Solvent and Heat to Clay Minerals in Shaly Sandstone

Core cleaning could be complicated for samples that contain a high amount of clays. Some clays are delicate and exposure to solvent and heat would damage or alter its properties. In this study, we investigated the effect of direct exposure of solvent and heat to clay mineral properties based on petrographical data from X-Ray Diffraction (XRD), Fourier Transform Infrared Spectroscopy (FTIR), Field Emission Scanning Electron Microscope (FESEM) and Energy Dispersive X-Ray (EDX). Experiments were performed on sidewall core samples taken in a shaly sand zone. The FTIR data did not show any changes at the molecular level to the clay mineral after direct contact with the selected solvent. The FESEM images showed some illite floccules collapse in the samples exposed to oven-drying at 60 °C.

Presalt reservoirs of the Santos Basin: Cyclicity, electrofacies, and tectonic-sedimentary evolution

Presalt reservoirs of the Santos Basin accounted for more than 50% of Brazilian hydrocarbon production in the first two months of 2019. Its most important reservoirs are found in the Barra Velha Formation; thus understanding its genesis and geologic history is essential. This formation is composed of carbonates deposited in an alkaline lacustrine environment with a multiplicity of facies from boundstones and grainstones to mudstones. We have performed a sedimentary analysis based on the integration of sidewall core (SWC) samples and well logs from two wells coupled with seismic patterns discrimination to characterize the tectonic and depositional evolution of the Barra Velha Formation in a sector of the Outer High of the Santos Basin in this study. Our method initially consisted of the evaluation of well logs, aiming to identify shallowing and flooding upward cycles of the second and third orders for the paleoenvironmental conceptualization upper rift and sag phases. Then, we defined electrofacies through the integration of SWCs, gamma ray, and acoustic impedance logs using the crossplot approach. Finally, we described seismic patterns throughout the study area and correlated with results from well data analysis. Therefore, the Barra Velha Formation was subdivided into three zones: the lower, intermediate, and upper zones. Well 1 has a facies association characteristic of a proximal and stable environment during deposition, whereas well 2 initially presents in a distal environment sedimentation that evolves to a more proximal setting. This fact evidenced differences with respect to base-level variations indicating compartmentalization within the lacustrine environment of the upper rift and sag phase that corroborated with the detailed seismic pattern interpretation of the study area.

Pore structure and fluid uptake of the Yeso, Abo, and Cisco Formations in the Permian Basin in southeast New Mexico, USA

There is a need for a petrophysical understanding of producing formations in the Northwest Shelf in southeast New Mexico. Working with six rotary sidewall core samples (dolomite, limestone, and sandstone), we have investigated the utility of mercury injection capillary pressure (MICP), contact angle, fluid imbibition, as well as logging analyses to evaluate the characteristics of pore structure and fluid uptake of the Yeso (Paddock and Blinebry members), Abo, and Cisco Formations. Results from MICP tests provide a variety of pore structure data including bulk and particle densities, porosity, pore-throat size distribution, permeability, and tortuosity. Two Abo dolomite samples indicate the highest porosities at greater than 15%, compared with 4%–7% for the other two dolomite samples from the Paddock and Blinebry members within the Yeso Formation. Most of the pore-throat sizes for these samples fall within the range of [Formula: see text]. The only exceptions are the Paddock member sample, which possesses a higher percentage of larger pores ([Formula: see text]), and the dolomite sample from the Cisco Formation, which has most of its pore-throat sizes falling within the range of [Formula: see text]. From contact angle measurements, all samples are found to be oil-wet because n-decane spreads onto the rock surface much quicker than the other hydrophilic fluids (deionized water and brine). Imbibition tests reveal well-connected pore networks in all samples, with the highest values of imbibition slopes being recorded for the Abo samples. In addition, we used the crossplot of porosity and water saturation obtained from log analyses to derive a value for permeability at field scales. The porosity and permeability values, from log analyses as well as laboratory MICP and gas pycnometry-permeameter measurements, and at different observational scales, are generally consistent. The overall results provide a snapshot of the pore structure characteristics, from limited samples but using integrated approaches and scales, of these formations.

Digital petrography: Mineralogy and porosity identification using machine learning algorithms in petrographic thin section images

Images represent a large and efficient source of geological information from oil exploration. To better analyze them, well-known machine learning algorithms are used to extract mineralogy and porosity data from petrographic thin section images. Microscopic petrographic analysis allows obtaining images from thin sections in the visible spectrum. They are used to evaluate depositional environments and diagenetic processes during the formation of sedimentary basins. However, that is an activity subjected to the petrographer's experience. Data from other sources, such as chemical microanalysis, provide quantitative information that might assist in petrographic evaluation, but they are expensive and time-consuming. The main objective is to create models that systematically interprets mineralogy and porosity from images acquired of optical microscopic analysis using machine learning algorithms, standardizing descriptions and reducing subjectivity and human errors during thin sections analysis. Image segmentation models are created with representative classes of the rocks' mineralogy and porosity. Datasets were selected from images originated from thin sections of carbonate rocks, which are prepared from sidewall core samples of oil wells, specifically from the pre-salt reservoirs of Santos Basin, on the southeast coast of Brazil. These models use discrete convolutional filters followed by artificial neural networks and random forest classifiers. A number of configurations were tested, using different convolutional filters and classifier's parameters. Five models were created: 1. mineralogical model using artificial neural network; 2. mineralogical model using random forest; 3. mineralogical model using random forest validated by chemical measurements; 4. porosity model using artificial neural networks; and 5. porosity model using random forest. They were evaluated through the use of 10-fold cross-validation tests and by correlation with chemical microanalysis. Correlation between the two technique's relative occurrences for each mineral phase shows a root mean square error of 8.99% and a coefficient of determination of 0.82. That demonstrates how well models can generalize.

Petrographic Characterization of Selected Sidewall Core Samples from NG-1 Well, Niger Delta, Nigeria: Palaeoclimatic Implication

Petrographic investigation of sandstones from Agbada Formation in NG-1 well was undertaken in order to petrographically characterize the sandstones. Petrographic examination of the sandstone shows that the sandstones are mineralogically mature and poorly to moderately sorted quartz arenite. Compositionally, made up of monocrystalline quartz (90-96%), polycrystalline quartz (7-2%), feldspar (2-5%), rock fragments &lt; 3%, silica, hematite cement and clay matrix. Abundant of monocrystalline quartz with marginal undulose extinction over polycrystalline quartz suggest igneous source derivatives. Presence of close packing, point and concavo – convex contacts, weathered plagioclase feldspar, grain dissolution, and fabric imprints indicates intermediate diagenesis. Consideration of petrographic attributes and paleoclimatic discrimination plot inferred semi-humid to humid palaeoclimates.

Characterization of subaerial volcanic facies using acoustic image logs: Lithofacies and log-facies of a lava-flow deposit in the Brazilian pre-salt, deepwater of Santos Basin

Abstract Volcanic rock facies characterization in subsurface log data have always being challenging. Even though considerable types of well logs are acquired, the results achieved on facies characterization with the conventional log suits are very limited. Conversely, high-resolution borehole image logs calibrated with side wall core samples can provide the necessary structural and textural information for facies definitions. In this case study, an integration of good quality acoustic image log data, side wall core petrography and geochemical analyses provided a good understanding of volcanic facies and stratigraphic relationships. Additionally, outcrop data from the analogous Serra Geral Formation and other Large Igneous Provinces were used for comparison. In the studied well, from Santos basin, Brazil, it was possible to identify several kinds of subaerial basaltic lava flow units, such as compound pahoehoe, sheet pahoehoe and rubbly pahoehoe lava flows. Vesicles, amygdales, vesicle cylinders, sub-horizontal vesicle sheets, autobreccias and entablature are some of the structures described in this study. As a result, 2 image catalogues of subaerial volcanic rocks were produced characterizing facies and flow units along with a stratigraphic model of the history of this volcanism. This is the first time that pahoehoe lava flow units could be characterized at an offshore Brazilian basin. The results achieved are important for the understanding of the Cretaceous volcanism events in the pre-salt layer and also provide support for the evaluation and geological modelling of the volcanic rocks in Santos Basin oil fields.